Methods and tools for multiple fracture placement along a wellbore

ABSTRACT

The invention discloses a tool for use in a wellbore, comprising: a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; and b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.61/346,306, filed May 19, 2010, which is incorporated herein byreference in its entirety.

FIELD OF THE INVENTION

The invention relates to methods for treating subterranean formations.More particularly, the invention relates to a tool for fracturingsubterranean formations.

BACKGROUND

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.

Hydrocarbons (oil, condensate, and gas) are typically produced fromwells that are drilled into the formations containing them. For avariety of reasons, such as inherently low permeability of thereservoirs or damage to the formation caused by drilling and completionof the well, the flow of hydrocarbons into the well is undesirably low.In this case, the well is “stimulated” for example using hydraulicfracturing, chemical (usually acid) stimulation, or a combination of thetwo (called acid fracturing or fracture acidizing).

In hydraulic and acid fracturing, a first, viscous fluid called the padis typically injected into the formation to initiate and propagate thefracture. This is followed by a second fluid that contains a proppant tokeep the fracture open after the pumping pressure is released. Granularproppant materials may include sand, ceramic beads, or other materials.In “acid” fracturing, the second fluid contains an acid or otherchemical such as a chelating agent that can dissolve part of the rock,causing irregular etching of the fracture face and removal of some ofthe mineral matter, resulting in the fracture not completely closingwhen the pumping is stopped. Occasionally, hydraulic fracturing can bedone without a highly viscosified fluid (i.e., slick water) to minimizethe damage caused by polymers or the cost of other viscosifiers.

It is an object of the present invention to provide an improved methodof fracturing by using a new tool deployed in the well.

SUMMARY

In a first aspect, a tool for use in a wellbore, comprises a tubularelongated member; openings on the tubular member able to be close with avalve or a sleeve; swellable packers positioned between said opening onthe tubular member; and a control unit; the control unit operating thevalve or sleeve for fracturing a subterranean formation in a wellbore,in the stages: (a) fracturing the subterranean formation through a firststage at predefined first locations; and (b) fracturing the subterraneanformation through a second stage at second location(s) wherein eachlocation from the second location(s) is localized between the predefinedfirst locations.

In a second aspect, a tool for use in a wellbore, comprises a tubularelongated member; openings on the tubular member able to be close with avalve or a sleeve; swellable packers positioned between said opening onthe tubular member; and a control unit; the control unit operating thevalve or sleeve for fracturing a subterranean formation in a wellbore,in the stages: (a) fracturing the subterranean formation through a firststage at predefined first locations; (b) fracturing the subterraneanformation through a second stage at second location(s) wherein eachlocation from the second location(s) is localized between the predefinedfirst locations; and (c) fracturing the subterranean formation through athird stage at third locations wherein each location from the thirdlocations is localized between the one of the predefined first locationsand one of the second location(s).

In a second aspect, a tool for use in a wellbore, comprises a tubularelongated member; openings on the tubular member able to be close with avalve or a sleeve; swellable packers positioned between said opening onthe tubular member; and a control unit; the control unit operating thevalve or sleeve for fracturing a subterranean formation in a wellbore,in the stages: (a) fracturing the subterranean formation through a firststage at predefined first locations; (b) fracturing the subterraneanformation through a second stage at second location(s) wherein eachlocation from the second location(s) is localized between the predefinedfirst locations; (c) fracturing the subterranean formation through athird stage at third locations wherein each location from the thirdlocations is localized between the one of the predefined first locationsand one of the second location(s); and (d) fracturing the subterraneanformation through a n-stage at n locations wherein each location fromthe n locations is localized between the one of the preceding locations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1 a, 1 b, 1 c, 1 d and 1 e are used as an example to illustratethe sequence of hydraulic fracturing according to embodiments disclosedherewith.

FIGS. 2 a and 2 b illustrate the symmetrical effect that result in thethird stage fracture (numbered 3) of the previous embodiment in FIG. 1a.

FIGS. 3 a, 3 b and 3 c illustrate schematically tools according toembodiments disclosed herewith.

FIGS. 4 a, 4 b, 4 c and 4 d show example of stages to illustrate thesequence of hydraulic fracturing according to embodiments disclosedherewith.

DESCRIPTION

At the outset, it should be noted that in the development of any actualembodiments, numerous implementation-specific decisions must be made toachieve the developer's specific goals, such as compliance with systemand business related constraints, which can vary from one implementationto another. Moreover, it will be appreciated that such a developmenteffort might be complex and time consuming but would nevertheless be aroutine undertaking for those of ordinary skill in the art having thebenefit of this disclosure.

The description and examples are presented solely for the purpose ofillustrating embodiments of the invention and should not be construed asa limitation to the scope and applicability of the invention. In thesummary of the invention and this detailed description, each numericalvalue should be read once as modified by the term “about” (unlessalready expressly so modified), and then read again as not so modifiedunless otherwise indicated in context. Also, in the summary of theinvention and this detailed description, it should be understood that aconcentration range listed or described as being useful, suitable, orthe like, is intended that any and every concentration within the range,including the end points, is to be considered as having been stated. Forexample, “a range of from 1 to 10” is to be read as indicating each andevery possible number along the continuum between about 1 and about 10.Thus, even if specific data points within the range, or even no datapoints within the range, are explicitly identified or refer to only afew specific, it is to be understood that inventors appreciate andunderstand that any and all data points within the range are to beconsidered to have been specified, and that inventors possession of theentire range and all points within the range disclosed and enabled theentire range and all points within the range.

The application discloses a method of delivery for more closely spacedmultiple hydraulic fracture treatments along a deviated, horizontal orextended reach well. These fractures are typically placed insequence/stages starting from the toe of the well and moving towards theheel. It has been noted that increasing the number of hydraulic fracturetreatments along horizontal wells, in particular for shale gas wells,results in significant increase of the production. Shale gas formationcharacteristics seem to favor closer spacing fracture treatments thaneconomically advisable in more permeable reservoirs. However, there is alimit as to how closely the fractures can be placed as each fracturealters the stress state in the formations around it, which can interferewith the outcome of the subsequent fracturing treatment/stage aimed atpropagating a fracture within the affected area and can impactnegatively its intended initiation, propagation, orientation, etc.

A method of fracturing a subterranean formation in a wellbore,comprises: fracturing the subterranean formation through a first stageat predefined first locations; and fracturing the subterranean formationthrough a second stage at second location(s) wherein each location fromthe second location(s) is localized between the predefined firstlocations. Each location from the second location(s) may be localized inthe middle between the predefined first locations. The method mayfurther comprise fracturing the subterranean formation through a thirdstage at third locations wherein each location from the third locationsis localized between the one of the predefined first locations and oneof the second location(s). Each location from the third locations may belocalized in the middle between the one of the predefined firstlocations and one of the second location(s). The method may furthercomprise fracturing the subterranean formation through a n-stage at nlocations wherein each location from the n locations is localizedbetween the one of the preceding locations. Each location from the nlocations may be localized in the middle between the one of thepreceding locations. In one embodiment, the wellbore is horizontaland/or the subterranean formation contains at least partially rockmaterial which is shale.

The tools and method outlined in this application enable the placementof more closely spaced fractures intersecting the wellbore. The methodproposed consist of using specialized equipment, which enablesalternating the fracture placement order so that in a first phase,fractures are placed far enough from each other to avoid interferenceand in a second phase another set of fractures are created half waybetween the fractures of the first phase. Symmetry allows the second setof fractures to propagate in the intended direction parallel to thefirst set.

FIGS. 1 a, 1 b and 1 c are used as an example to illustrate the sequenceof hydraulic fracturing according to embodiments disclosed herewith. Adownhole equipment is deployed in the wellbore and allows anon-consecutive sequence for fracturing. Instead of pumping stages 1-5sequentially along the wellbore starting from the toe (FIG. 1 a—priorart), we would pump stages 1, 2, 3 with longer spacing and then go backand pump stages 4 and 5 between the fractures 1-2 and 2-3 respectively(FIG. 1 b). We can also place additional fractures between 1 and 4, thenbetween 4 and 2 . . . if economics are positive for such action, as longas higher fracturing pressures could be handled in practice (FIG. 1 c).FIGS. 1 d and 1 e show another type of stimulation starting at the heel.

FIG. 2 illustrates the symmetrical effect that result in the third stagefracture (number 3) being able to propagate parallel to stages 1 and 2.Placing fracture 3 before fracture 2 would result in fracture 3 movingaway from fracture 1 and tending to initiate along the wellbore due tothe stress regime created by fracture 1.

According to a first embodiment, downhole sliding sleeves 32 or otherdevices with similar functionality are deployed on a pipe 30 that isequipped with packers 31 that isolate the annulus space 34 between thepipe and the wellbore around each set of sliding sleeves/devices. Thewellbore could be open hole 40, cased/un-cemented (slotted,pre-perforated, etc) or cased/cemented & perforated in multiple clustersthat would be grouped to fall between the isolation packers. Optionally,the cased hole could be pre-perforated in clusters. The space betweenpackers could contain multiple clusters of perforations. In one or moreembodiments, the opening of the valve/sliding sleeve could detonatecharges deployed simultaneously with the valves, which would perforatethe casing. The packer elements could be simply swellable packers orcould be activated by mechanical, hydraulic and electrical means or acombination. A fracture 50 is generated. In general the well comprises acasing 10 and a production packer 11. The frac valve operating tool 12may be deployed in the wellbore with a coiled tubing 13. FIG. 3 a is aview of such configuration.

The downhole sliding sleeves tool can include one or more subs and/orsections threadably connected to form a unitary body/mandrel having abore or flow path formed therethrough. In one or more embodiments, thetool can include one or more valve sections, one or more slidingsleeves, one or more sealing devices and/or one or more openings orradial apertures formed therethrough to provide fluid communicationbetween the inner bore and external surface of the tool. The toolcomprises a lower end (localized at the toe of the wellbore) and anupper end. In one or more embodiments, the lower end can be adapted toreceive or otherwise connect to a drill string, a similar tool or otherdownhole tool, while the upper end can be adapted to receive orotherwise connect a similar tool, a coiled tubing, a drill string orother types of downhole tools. In one or more embodiments, the tool canbe fabricated from any suitable material, including metallic,non-metallic, and metallic/nonmetallic composite materials. In one ormore embodiments the tool may be done from a drillable material. In oneor more embodiments, the end of the tool can include one or morethreaded ends to permit the connection of a casing string or additionalcombination tool sections as described herein.

In one or more embodiments, the sealing devices positioned on theoutside surface from the unitary body are swellable packers. Theswellable packers are localized on both side of the radial openings(lower and upper front) as shown on FIG. 3 a. When the swellable packersare activated the zone of the wellbore between both packers is isolated.The swellable packers may be activated with oil based, water based, oralternative fluids. The packers may also be set by mechanical or thermalmeans.

In the fracturing process, fluid communication between the interior andexterior of the tool is permitted. Such fluid communication isadvantageous for example when it is necessary to fracture thehydrocarbon bearing zones surrounding the tool by pumping a slurry athigh pressure through the casing string, into the bore of the tool. Thehigh pressure slurry passes through the tool and exits the tool via theradial openings when the valve or the sliding sleeve is opened.

In one or more embodiments, the tool deployed could be manipulated viacoiled tubing. The coiled tubing could be equipped with a retractablekey that engages the devices selectively to mechanically open or closethem as needed to affect the sequence described above. The coiled tubingcould be left in the wellbore during the fracture treatments and couldcarry monitoring equipment includingpressure/temperature/optical/geophysical sensors. It could also be usedto deliver specialty materials that are used to better monitor thetreatments or modify properties of pumped materials.

In one or more embodiments, these tools can be designed and deployed sothat they can be controlled electrically or hydraulically via a controlcable 16 or hydraulic line (FIG. 3 b). The elongated pipe may be atubing 15. They could also be designed to be operated wirelessly viaacoustic or electromagnetic signals. The signals could be sent remotelyfrom surface or using a downhole signal generator/transmitter. Theelectromagnetic or acoustic triggers of the devices could also bedeployed via wireline with/without tractor or via coiled tubing. Alsosome sensor 60 can be used to monitor parameters of the wellbore forexample to control efficiency of the fracture. In one or moreembodiments, the tools can be operated open or closed via pressuresignals applied from surface that are uniquely coded for each devices.The operator would thus be able to selectively open or close theappropriate device to allow the fracture treatments to be placed as perthe sequence described above. In one or more embodiments, the signal canbe transmitted to tool by pumping a RFID tag to open or close the tool.Each tool could be uniquely coded and pumped RFID tag will havecorresponding code.

In one or more embodiments, the tool can be run with liner 19 andcemented in place (FIG. 3 c). A liner hanger 17 connects the liner 19 tothe casing 10. The cement 18 provides isolation between zones or fracvalves. The cemented frac valves or sleeves would operate in the samemanner.

In one or more embodiments, the technique could be applied to duallateral (could also be expanded to tri-lateral, quad-lateral or morecomplex wellbores. As well the very similar process could be applied tomultiple horizontal wellbores. FIG. 4 shows a graphical representationhow this type of process could be applied. Please note that forsimplicity of explanation in the figures the fractures for each stageare only shown propagating in one direction. In line with hydraulicfracturing theory it is normally the case that a second “wing” of thefracture will propagate at approximately 180-degrees.

In one or more embodiments, the technique could be applied inconjunction for simultaneous multistage stimulation of long horizontalwells. In an open hole environment, the formation is notched usingmechanical means, water jetting, or perforating charges to createfracturing initiation sites in such a manner as to enable simultaneouspropagation of multiple fractures along the horizontal wells. More thanone set of notches may be used and the fracturing treatment may beperformed in two stages or more. The first stage treats the first set ofnotches placed far enough from each other such that the stress changesinduced by the propagating fractures do not create interference.Following the first stage, a new set of notches are created half waybetween the notches/fractures of the first stage and a secondstage/treatment is pumped to propagate a new set of fractures. Dependingon geometry of the fractures created in the first stage, the level andorientation of local stress alteration will be different. Therefore, thegeometry of the second set of the notches will be designed based on thestress alteration created by the first set of fractures and by takinginto account the mechanical properties of local rock so that thefracturing pressure required to initiate new set of fractures can bemanaged. The new notches could be wider and deeper than the previousset, or the notch tips could be sharper. The tools will have focusinjection ports pin pointed at the notch locations narrowly packed offby the packers to ensure that the fractures are controllably initiatedfrom the notches. The process can be repeated if a higher density offractures intersecting the wellbore is economically desirable.

The possibilities for creating the activation of the mechanism(s) tocreate fracture initiation points and provide isolation for thestimulation can range all the way from the simplest, more time-consumingmethods (aka “dumb completion”) to the most technically complex andcontinuous methods (aka “intelligent or smart completion”). One skilledin the art could envision a number of ways to achieve the overall intentof the invention.

The foregoing disclosure and description of the invention isillustrative and explanatory thereof and it can be readily appreciatedby those skilled in the art that various changes in the size, shape andmaterials, as well as in the details of the illustrated construction orcombinations of the elements described herein can be made withoutdeparting from the spirit of the invention.

1. A tool for use in a wellbore, comprising: a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; and b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations.
 2. The tool of claim 1, wherein the wellbore has a section substantially deviated or horizontal.
 3. The tool of claim 1, wherein the wellbore has a horizontal section where the tool is placed.
 4. The tool of claim 1, wherein the control unit is a downhole tool, a coiled tubing or a drill string.
 5. The tool of claim 1, wherein the tool is deployed during completion.
 6. The tool of claim 1, wherein the swellable packers are activated with oil based, water based, or alternative fluids.
 7. The tool of claim 1, wherein the swellable packers set by mechanical or thermal means.
 8. A tool for use in a wellbore, comprising: a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations; and c. fracturing the subterranean formation through a third stage at third locations wherein each location from the third locations is localized between the one of the predefined first locations and one of the second location(s).
 9. The tool of claim 9, wherein the wellbore has a section substantially deviated or horizontal.
 10. The tool of claim 9, wherein the wellbore has a horizontal section where the tool is placed.
 11. The tool of claim 9, wherein the control unit is a downhole tool, a coiled tubing or a drill string.
 12. The tool of claim 9, wherein the tool is deployed during completion.
 13. The tool of claim 9, wherein the swellable packers are activated with oil based, water based, or alternative fluids.
 14. The tool of claim 9, wherein the swellable packers set by mechanical or thermal means.
 15. A tool for use in a wellbore, comprising: a tubular elongated member; openings on the tubular member able to be close with a valve or a sleeve; swellable packers positioned between said opening on the tubular member; and a control unit; the control unit operating the valve or sleeve for fracturing a subterranean formation in a wellbore, in the stages: a. fracturing the subterranean formation through a first stage at predefined first locations; b. fracturing the subterranean formation through a second stage at second location(s) wherein each location from the second location(s) is localized between the predefined first locations; c. fracturing the subterranean formation through a third stage at third locations wherein each location from the third locations is localized between the one of the predefined first locations and one of the second location(s); and d. fracturing the subterranean formation through a n-stage at n locations wherein each location from the n locations is localized between the one of the preceding locations.
 16. The tool of claim 15, wherein the wellbore has a section substantially deviated or horizontal.
 17. The tool of claim 15, wherein the wellbore has a horizontal section where the tool is placed.
 18. The tool of claim 15, wherein the control unit is a downhole tool, a coiled tubing or a drill string.
 19. The tool of claim 15, wherein the tool is deployed during completion.
 20. The tool of claim 15, wherein the swellable packers are activated with oil based, water based, or alternative fluids.
 21. The tool of claim 15, wherein the swellable packers set by mechanical or thermal means. 